1. Field of the Invention
The present disclosure relates to a method of identifying gas in geological formations and is particularly related to identifying gas from Nuclear Magnetic Resonance (NMR) data obtained in a region of low magnetic field gradient in a geological formation.
2. Description of the Related Art
Oil or gas wells are often surveyed to determine one or more geological, petrophysical, geophysical, and well production properties (“parameters of interest”) using electronic measuring instruments conveyed into the borehole by an umbilical such as a cable, a wireline, slickline, drill pipe or coiled tubing. A variety of techniques are utilized in determining the presence and estimation of quantities of hydrocarbons (oil and gas) in earth formations. These methods are designed to determine among other things, the resistivity, porosity and permeability of the rock formation surrounding the wellbore drilled for recovering the hydrocarbons. Typically, the tools designed to provide the desired information are used to log the wellbore. More recently, wellbores have been logged while drilling, which is referred to as measurement-while-drilling (MWD) or logging-while-drilling (LWD).
One recently evolving technique involves utilizing Nuclear Magnetic Resonance (NMR) logging tools and methods for determining, among other things, porosity, hydrocarbon saturation and permeability of the rock formations. The NMR logging tools are utilized to excite the nuclei of the liquids in the geological formations surrounding the wellbore so that certain parameters such as spin density, longitudinal relaxation time (generally referred to in the art as T1) and transverse relaxation time (generally referred to as T2) of the geological formations can be measured. From such measurements, porosity, permeability and hydrocarbon saturation are determined. These quantities provide valuable information about the make-up of the geological formations and the amount of extractable hydrocarbons.
NMR tools generate a uniform or near uniform static magnetic field in a region of interest surrounding the wellbore. NMR operates based on the fact that the nuclei of many elements have angular momentum (spin) and a magnetic moment. The nuclei have a characteristic Larmor resonant frequency related to the magnitude of the magnetic field in their locality. Over time the nuclear spins align themselves along an externally applied magnetic field. This equilibrium situation can be disturbed by a pulse of an oscillating magnetic field, which tips the spins with resonant frequency within the bandwidth of the oscillating magnetic field away from the static field direction. For spins that are exactly on resonance, the angle θ through which the spins are tipped is given by the equation:θ=γB1tp.  (1)where γ is the gyromagnetic ratio, B1 is the effective field strength of the oscillating field and tp is the duration of the RF pulse.
After tipping, the spins precess around the static field at a particular frequency known as the Larmor frequency ω0, given byω=γB0  (2)where B0 is the static field intensity. At the same time, the spins return to the equilibrium direction (i.e., aligned with the static field) according to an exponential decay time known as the spin-lattice relaxation time, or longitudinal relaxation time, T1. For hydrogen nuclei, γ/2π=4258 Hz/Gauss, so that a static field of 235 Gauss produces a precession frequency of 1 MHz. The T1 of fluid in pores is controlled totally by the molecular environment and is typically ten to one thousand milliseconds in rocks.
Typically, measurement of NMR-related phenomena in the earth formation is performed by allowing some time for the static magnetic field to polarize nuclei in the formation in a direction substantially along the direction of the static magnetic field. A first one of the radio frequency (RF) pulses passed through the antenna has a magnitude and duration selected to reorient the nuclear magnetization by about 90 degrees from its previous orientation. This pulse is referred to in the prior art as the π/2-pulse, the 90°-pulse, and the excitation pulse, among others. After a selected wait time (TW), successive RF pulses are passed through the antenna, each of these having a magnitude and duration selected to reorient the nuclear spin axes by about 180 degrees from their immediately previous orientations in order to enable the nuclear spin axes to “rephase” or realign with each other. These rephasing pulses are referred to in the prior art as the B-pulses, the 180°-pulses, π-pulses, and refocusing pulses, among others. The induced signals, known as “spin echoes”, are generally measured during the time interval between each successive one of the “180 degree” RF pulses. The succession of spin echo measurements is generally known as a “sequence”. The amplitude of the spin echo signals, and the rate at which the spin echo amplitudes change during a measurement sequence, are related to properties of interest of the earth formations, such as fractional volume of pore space (porosity) and the properties of fluids present in the pore spaces. The frequency of the RF magnetic field needed to reorient the nuclear magnetization, which is the frequency of the spin echo signals, is related to the amplitude of the static magnetic field and a factor, known as the gyromagnetic ratio γ, which is unique to each isotope. For evaluation of earth formations, the static magnetic field amplitude and RF magnetic field frequency are typically selected to excite NMR phenomena in hydrogen nuclei, although other nuclei may be used for NMR evaluation of earth formations.
A standard sequence of RF pulses used to measure the true transversal relaxation (not related to the macroscopic inhomogeneity of the static magnetic field) is the Carr-Purcell-Meiboom-Gill (CPMG) sequence. The CPMG sequence is described, for instance, in Experimental Pulse NMR: A Nuts and Bolts Approach by E. Fukushima, S. B. W. Roeder. This sequence comprises a first excitation RF pulse (π/2 pulse) that tilts the magnetization from a Z-axis into the X-Y plane followed by a plurality of refocusing RF pulses (π pulses). The period of repetition of the plurality of the refocusing pulses is twice the length of time between the center of the excitation pulse and the center of the first refocusing pulse. The spin echo signal, which results from refocusing the spin isochromats, appears between refocusing pulses. The amplitudes of the echoes represent points on a T2 relaxation curve. This curve is then decomposable into exponential terms in order to differentiate between the types of substances present and/or, in the case of a fluid trapped in a porous structure, to characterize the porous media.
The CPMG sequence uses a 90° tipping pulse followed by a plurality of 180° refocusing pulses. Similar results may be obtained by using refocusing pulses having a tipping angle in the range from 135° to 180°. See U.S. Pat. No. 6,466,013 to Hawkes et al., and U.S. Pat. No. 6,163,153 to Reiderman, both having the same assignee as the present disclosure. The pulse sequence described therein may be referred to as the Optimal Rephasing Pulse Sequence (ORPS).
It is difficult to identify and estimate gas quantities using a standard CPMG sequence due to the relative strengths of the signals of liquid and gas phases. Prior methods of NMR based hydrocarbon gas identification are based on one of two approaches. The first approach utilizes two or more wait times (TW) to elicit a contrast in polarization between the liquid phase fluids and the hydrocarbon gas. This method relies on the longitudinal relaxation time T1 being different between gas and liquids as well as a proper selection of TW parameters. A typical realization of this method is described in U.S. Pat. No. 5,498,960, by Vinegar et al. This method is limited in that the formation does not generally contain slowly relaxing liquids such that the polarization contrast between liquid and gas is adequate. Low-viscosity oil and water in carbonate rocks may have long T1 values comparable to that of gas, thereby invalidating an approach based on polarization contrast.
The second approach is based on determining the diffusion contrast between gas and liquid phases. A magnetic field gradient is typically used to elicit the diffusion contrast, since the fluid NMR signal decay contrast depends on
                              exp          ⁡                      (                          -                              t                                  T                                      2                    ⁢                                                                                  ⁢                    D                                                                        )                          ⁢                                  ⁢        where                            (        3        )                                                      1                          T                              2                ⁢                                                                  ⁢                D                                              =                                                    γ                2                            ·                              G                2                            ·                              TE                2                            ·              D                        12                          ,                            (        4        )            where γ is the gyromagnetic ratio of the nucleus being measured, G is the magnetic field gradient, TE is the data acquisition sequence parameter called interecho time, and D is the diffusivity of the fluid. The selection of the combination of G and TE is critical to the discernment of the liquids and gas. The strength of the field gradient is often determined by the design of the magnetic field configuration, and the operating frequencies thus are substantially limited to vary. Although conceptually it is possible to select a long TE value to compensate for a low field gradient, in practice, the longer TE selection is also known to be limited. Long TE reduces the echo train sampling rate and is detrimental to fast relaxing components, especially for those with T2 smaller than or comparable to TE. Thus the long TE echo train may result in large uncertainty in estimations of porosity, Clay Bound Water (CBW), and Bulk Volume Irreducible (BVI), for example.
More recently a combination of the T1 vs. apparent T2 method has been used for gas identification. U.S. Pat. No. 7,298,142 to Hursan et al. and assigned to Baker Hughes Incorporated describes the method of using a T1/T2app ratio for gas identification. This method utilizes a contrast between the intrinsic relaxation time and the apparent relaxation time. However, since the apparent relaxation time is
                              1                      T                          2              ⁢                                                          ⁢              app                                      =                                            1                              T                                                      2                    ⁢                                                                                  ⁢                    intr                                    ⁢                                                                                                              +                          1                              T                                  2                  ⁢                                                                          ⁢                  D                                                              ≈                                    1                              T                1                                      +                          1                              T                                  2                  ⁢                                                                          ⁢                  D                                                                                        (        3        )            the method still relies on the presence of an adequate gradient strength.
An NMR logging tool includes a magnet that generates a static magnetic field in a sensitive volume of an earth formation to align nuclear spins within. Depending on the configuration and geometry of the magnet, the corresponding magnetic field in the sensitive volume may either be nearly uniform, or have a linear or non-linear gradient. This gradient can be calculated, and its effect on the data interpretation can be accounted for quantitatively.
For an NMR logging tool positioned inside a wellbore, the static magnetic field penetrates to the porous rock formation and also produces magnetization. A formation rock typically contains matrix and a fluid (liquid or gas) occupying the pore space within the matrix. The minerals of the matrix have a magnetic susceptibility of χm which may be different from that of the fluids, χf. Thus, at the interface of the matrix and the fluid, an “internal field gradient”, arising from the magnetic field susceptibility difference, occurs, as shown in Eq. (5):
                              G          int                =                                                            (                                                      χ                    m                                    -                                      χ                    f                                                  )                            ·              H                        r                    -                                                    Δ                ⁢                                                                  ⁢                                  χ                  ·                  H                                            r                        .                                              (        5        )            
The magnitude of the internal field gradient varies from one point to another in the pore space, and is dependent on the magnetic field strength, H, and the curvature, 1/r, at the interface. Because of the heterogeneity in rock minerals and pore geometry, neither χm nor r can be well estimated, leaving a great uncertainty in the value of Gint. Therefore, the effect of Gint on NMR logging data interpretation may not be well accounted for.
A magnetic field gradient affects NMR measurements by increasing the spin dephasing, thereby resulting in the enhancement of free-induction decay, spin-echo or echo train decay. In an CPMG echo train, for example, the enhancement of echo train decay can be described as an introduction of an additional decay rate,
                              1                      T                          2              ⁢                                                          ⁢              D                                      =                                                            (                                  γ                  ·                  G                  ·                  TE                                )                            2                        ·            D                    12                                    (        6        )            where γ is the gyromagnetic ratio, G is the magnetic field gradient which includes both the NMR instrument designed gradient and the internal field gradient, and TE is the echo spacing. The diffusivity, D, is a fluid property.
The uncertainty of Gint introduces uncertainty in T2D, resulting in mainly two detrimental effects on NMR log data analysis. Firstly, the uncertainty arising from Gint results in an uncertain relation between T2int and T2app and therefore in uncertainty of formation pore size distribution estimate. The relation between T2int and T2app is:
                              1                      T                                          2                ⁢                                                                  ⁢                int                            ⁢                                                                                  =                              1                          T                              2                ⁢                                                                  ⁢                app                                              -                                    1                              T                                  2                  ⁢                                                                          ⁢                  D                                                      .                                              (        7        )            Since NMR-based pore size distribution analysis is based on intrinsic relaxation time distribution T2int, but the measured echo decay corresponds to apparent relaxation time distribution T2app, any uncertainty arising from Gint results in uncertainty in the formation pore size distribution. Secondly, the uncertainty of Gint leads to error in fluid identification and/or property analysis, since discerning different fluid types often is performed by contrasting their T2int or T2D or both.
The effect of T2D on the value of T2int can be reduced by making TE small. On the other hand, if one relies on the diffusivity contrast for fluid typing, one is not interested in reducing the TE to minimize the diffusion contrast in echo decay. Thus, there is a need for a method of identifying a gas saturation using NMR sequences in low-field gradients.